Hydraulic fracturing is used by the petroleum industry to increase well productivity or injectivity by creating highly conductive paths some distance from the wellbore into the formation. The fracturing is created by injecting suitable fluids into the well under pressure until the reservoir rock fractures. In order to create a fracture, enough energy must be provided to overcome the native overburden pressures which then causes failure, or fracture, of the reservoir material. The fracturing fluid usually carries a proppant, such as 20-40 mesh sand, bauxite, glass beads, and the like, suspended in the fracturing fluid and transported into the fracture. The proppant then keeps the newly formed fractures from closing when the pressure is released.
Hydraulic fracturing has been used for many years and a variety of fluids have been developed over the years that can withstand the high pump rates, shear stresses, and high temperatures and pressures a fracturing fluid is often exposed to. Most of the fracturing fluids used today are aqueous based gels, emulsions, or foams.
Common gelling agents for water based fracturing fluids are high molecular weight polymers, such as borate-crosslinked guar/hydroxypropyl guar (HPG), hydroxyethylcellulose (HEC), and polyacrylamides. Carboxymethylhydroxy guar cross-linked with zirconium has been used for high temperature wells. See Frac Pack Technology Still Evolving, Oil and Gas Journal. Oct. 23, 1995, pp. 60-70. The ability of a fluid to effectively carry proppant is dependent on such things as the viscosity and density of the fluid. Small amounts of polymers can greatly thicken aqueous based fluids. At relatively low temperatures an aqueous liquid thickened with only polymers will normally have sufficient viscosity to suspend the proppant during the fracturing process. On the other hand, at higher temperatures, the viscosity is greatly decreased and it is necessary to crosslink the polymer with borate, or other metal ions, to maintain sufficient viscosity. Borate crosslinked guar fluids using less than 30 pounds guar per 1000 gallons of fluid have been used successfully in formations up to 135.degree. C. Such fluids can be effective up to temperatures of 177.degree. C. with increased guar loadings
A disadvantage associated with the above systems is related to the high molecular weight polymer solids which are often cross-linked to further increase molecular weight. The resulting high molecular weight polymers will typically contain insoluble materials that tend to filter out in the formation, or fractures, after the fracturing treatment. This reduces the conductivity or permeability of the formation and results in decreased well productivity. Expensive and often corrosive reagents, known as breakers, are commonly used to destroy the molecular backbone of these polymers, reducing the molecular weight, making it more soluble in surrounding fluids. This makes it easier to remove from the formation. Agents used as breakers are typically oxidizers or enzymes, but they are only partially effective. For example, cleanup of the polymer is typically less than about 80% and in many cases less than about 50%.
There are also foamed fracturing fluids which are commonly comprised of 75-80% gaseous nitrogen and 20-25% water or fluids. The ratio of the components affects the viscosity of the fluid. Foamed fracturing fluids are relatively clean, have good proppant suspension and carrying capabilities, and provide relatively easy cleanup of formation and fractures. The cost of foamed fracturing fluids is more attractive in shallow to medium depth wells because less liquids and additives are required. They become less cost effective at increased depths because more nitrogen is needed to produce foam at greater pressures. Further, more pumping horsepower is required at greater depths to compensate for the relatively low fluid density of the material that is being injected to overcome the relatively high fracturing pressures. In some cases it may not be possible to get the desired maximum proppant concentrations because the proppant must be blended with the fluid portion of the foam before being mixed with the gas.
A new type of fracturing fluid, a viscoelastic surfactant system, is described in U.S. Pat. No. 5,551,516, which is incorporated herein by reference. The system is described as having a texture similar to that of gelatin, making it an excellent particle suspension medium. Such systems are typically comprised of a water soluble salt, such as an ammonium or potassium chloride, and an organic stabilizing additive selected from the group of organic salts such as sodium salicylate, thickened by the addition of 1 to 8 wt. % of various cationic quaternized ammonium surfactants. The use of cationic quaternized ammonium surfactants as thickening agents with these salts is said to be stable to temperatures of about 110.degree.C. This viscoelastic surfactant system is described as being solids-free and having good viscosity and proppant transport capabilities. It also presents less of a cleanup problem of formation fractures when compared to polymer based systems. The viscoelastic surfactant fracturing fluid can be broken by contact with formation water or oil and needs no internal breakers to reduce viscosity so that it can be removed cleanly from the formation.
A potential problem with the above described viscoelastic surfactant system is that cationic surfactants can oil-wet formation rocks, thereby increasing the resistance of the oil flow through formation pore throats which are restricted by oil covered surfaces. It is generally felt that a water wet formation is more beneficial for production than an oil wet formation. Application of the above viscoelastic surfactant system is also restricted to temperatures below about 110.degree. C., and it appears to be most effective at temperatures below about 80.degree. C. Published literature reporting on the above system shows a dramatic drop in viscosity at temperatures above 80.degree. C. (SPE Publication #31114, February 1996). Many formations being drilled and fractured today have temperatures exceeding 110.degree. C.
Although various fracturing fluid formulations are presently used, there is still a need for improved fracturing fluids which do not have the disadvantages of either the polymer system that can damage the formation, or the disadvantage of the cationic viscoelastic surfactant systems which can undesirably oil-wet the formation rocks. There is also a need for fracturing fluids which are stable at elevated temperatures, especially at temperatures in excess of 110.degree. C.